A tubular casing string, termed “casing” is used when drilling wells to support the drill hole against collapse. Casing is hung with a casing hanger, or is otherwise supported such as with a casing slip assembly, within the central bore of a pressure-containing wellhead member called a casing head. A “primary seal” is formed between the casing head and the rough outer wall of the casing to prevent fluid flow between the outside of the casing and the casing head. The casing may extend upwardly from the casing head to a cut upper end, which is then contained within a pressure-containing wellhead member called a tubing head. The casing and tubing heads are connected at mating surfaces in a pressure tight connection. A string of production tubing is supported by the tubing head, to extend concentrically within the casing. The production tubing acts as a conduit for the oil, gas or water of the well. To seal the contents of the well from the primary seal between the casing and the casing head, one or more additional seals are used above the primary seal, between the tubing head and the casing. These one or more additional seals are termed “secondary seals”.
Metal seals are favoured to provide an extreme temperature, high pressure metal-to-metal barrier seal between metal surfaces in wellhead environments. When the metal sealing surfaces are machine finished surfaces, a large number of metal-to-metal seal designs may be used, such as an interference fit between tapered, machined metal surfaces. However, when the metal seal is to an un-machined or otherwise rough outer surface of a casing, it is more difficult to make a metal seal. The following patents show exemplary secondary seals to a rough casing: U.S. Pat. No. 4,646,845 to Boeker; U.S. Pat. No. 4,718,679 to Vyvial; U.S. Pat. No. 4,771,832 to Bridges; U.S. Pat. No. 4,911,245 to Adamek et al.; U.S. Pat. No. 5,158,326 to Anderson et al. and U.S. Pat. No. 5,183,268 to Wong et al.
Most metal seals to a rough casing have been made in wellheads in which considerable pressure may be exerted to energize the metal seal through the use of flanged connections between the wellhead members. However, for threaded unions between wellhead members, metal seals are more difficult to achieve, since the limited force which is applied to make the threaded connection may not be sufficient to energize the seal. In a threaded union, the wellhead members are held together by a threaded nut or collar that is tightened to a required torque using a wrench or a hammer. One exemplary threaded union is shown in U.S. Pat. No. Publication 2008/0185156 to Rodgers et al., in which a threaded collar between a tubing head and a casing head includes a set of left-hand threads and a set of right-hand threads to connect to the outer threads on the tubing and casing heads.
Thus, one disadvantage of most prior-art threaded unions is that they rely on elastomeric seals, and not metal seals, to achieve a pressure containing, fluid-tight joint between wellhead members. However, flanged connections between wellhead members are expensive to construct and time-consuming to assemble in the field. As the oil industry continues to move toward producing hydrocarbons at a lower cost, there is considerable interest in wellhead equipment that can be quickly assembled and disassembled. Threaded unions are much quicker and less expensive than flange connections to construct. However, reliable high-pressure metal-to-metal seals with a threaded unions continues to be a problem area for the industry.